Oil and gas are produced from wells penetrating subsurface hydrocarbon-bearing formations or reservoirs. Such reservoirs can be found at various depths in the subsurface of the earth. In gas-producing reservoirs, the gas and/or oil contained therein is compressed by the weight of the overlying earth. When the formation is breached by a well, the gas tends to flow into the well under formation pressure. Any other fluid in the formation, such as connate water trapped in the interstices of the sediments at the time the formation was deposited, also moves toward the well. Production of fluids from the well continues as long as the pressure in the well is less than the formation pressure. Eventually production slows and/or ceases either because formation pressure equals or falls below well pressure (borehole pressure). In the latter case, it has often been found that interstitial water filling the well exerts sufficient pressure to stop or sharply reduce production. A problem arises when the expense of removing the water becomes a substantial portion of, or exceeds the value of the hydrocarbon produced, thereby making it uneconomical to operate the gas and/or oil well. At times, up to 60% of the oil and or gas reserves may still be in the formation.
Many conventional approaches for removing liquid from an oil and gas well are disclosed in the prior art. Piston pumps are common and require either an electric or gas powered motor which is coupled by belts or gears to a reciprocating pump jack. The reciprocating motion of the pump jack, in turn, reciprocates a piston within a cylinder disposed within the well. As the piston reciprocates within the well, valves open and close, creating a low pressure in the well and drawing the oil to the surface. Centrifugal or rotary pumps, often found in water wells, also operate by either an electric or gas powered motor. Usually, the pump is attached directly to the shaft of the motor. The rotary motion of the veins reduces pressure in the well, thereby causing the fluid to flow up the well.
Major disadvantage with both piston and centrifugal pumps include mechanical fatigue and failure of moving parts and high maintenance and repair costs. Furthermore, such systems require large amounts of electricity or fuel to operate, making them more costly than passive systems. Typically, the expense of maintaining and operating such systems will eventually exceed the economic benefits returned and result in the well being shut in with up to 60% of the reserves still within the formation.
In gas producing wells another major disadvantage of conventional pumps such as electrically submersible pumps, is that their efficiency can be very low unless enough hydrostatic head is provided. In gas wells it is often valuable to totally remove the standing fluid to near the bottom of the wellbore where there is simply not enough allowable fluid column height and therefore not enough hydraulic head to allow such pumps to effectively operate. Furthermore, the well accumulation rate of liquids in gas wells can be very much lower than the rate at which such pumps must run which can result in a high frequency of pump shutdown events and an increased risk of such pumps running dry and burning up.
Therefore, there remains a long-felt need in the field of art for improved systems and processes for extracting fluid from a wellbore.